The invention is in the field of determination of petrophysical properties, including oil saturation, of medium using data from a Nuclear Magnetic Resonance (NMR) tool.
A variety of techniques have been utilized in determining the presence and in estimating quantities of hydrocarbons (oil and gas) in earth formations. These methods are designed to determine formation parameters, including among other things, porosity, fluid content, and permeability of the rock formation surrounding the wellbore drilled for recovering hydrocarbons. Typically, the tools designed to provide the desired information are used to log the wellbore. Much of the logging is done after the well bores have been drilled. More recently, wellbores have been logged while drilling of the wellbores, which is referred to as measurement-while-drilling (xe2x80x9cMWDxe2x80x9d) or logging-while-drilling (xe2x80x9cLWDxe2x80x9d). Measurements have also been made when tripping a drillstring out of a wellbore: this is called measurement-while-tripping (xe2x80x9cMWTxe2x80x9d).
One recently evolving technique involves utilizing Nuclear Magnetic Resonance (NMR) logging tools and methods for determining, among other things porosity, hydrocarbon saturation and permeability of the rock formations. The NMR logging tools are utilized to excite the nuclei of the fluids in the geological formations in the vicinity of the wellbore so that certain parameters such as spin density, longitudinal relaxation time (generally referred to in the art as xe2x80x9cT1xe2x80x9d), and transverse relaxation time (generally referred to as xe2x80x9cT2xe2x80x9d) of the geological formations can be estimated. From such measurements, porosity, permeability, and hydrocarbon saturation are determined, which provides valuable information about the make-up of the geological formations and the amount of extractable hydrocarbons.
A typical NMR tool generates a static magnetic field B0 in the vicinity of the wellbore, and an oscillating field B1 in a direction perpendicular to B0. This oscillating field is usually applied in the form of short duration pulses. The purpose of the B0 field is to polarize the magnetic moments of nuclei parallel to the static field and the purpose of the B1 field is to rotate the magnetic moments by an angle xcex8 controlled by the width tp and the amplitude B1 of the oscillating pulse. With the variation of the number of pulses, pulse duration, and pulse intervals, various pulse sequences can be designed to manipulate the magnetic moment, so that different aspects of the NMR properties can be obtained. For NMR logging, the most common sequence is the Carr-Purcell-Meiboom-Gill (xe2x80x9cCPMGxe2x80x9d) sequence that can be expressed as
TWxe2x88x9290xe2x88x92(txe2x88x92180xe2x88x92txe2x88x92echo)n
After being tipped by 90xc2x0, the magnetic moment precesses around the static field at a particular frequency known as the Larmor frequency xcfx890, given by xcfx890=xcex3B0, where B0 is the field strength of the static magnetic field and xcex3 is the gyromagnetic ratio. At the same time, the magnetic moments return to the equilibrium direction (i.e., aligned with the static field) according to a decay time known as the xe2x80x9cspin-lattice relaxation timexe2x80x9d or T1. Inhomogeneities of the B0 field result in dephasing of the magnetic moments and to remedy this, a 180xc2x0 pulse is included in the sequence to refocus the magnetic moments. This gives a sequence of n echo signals.
U.S. Pat. No. 5,023,551 issued to Kleinberg discloses an NMR pulse sequence that has an NMR pulse sequence for use in the borehole environment which combines a modified inversion recovery (FIR) pulse sequence with a series of more than two, and typically hundreds, of CPMG pulses according to
[Wixe2x88x92180xe2x88x92TWixe2x88x9290xe2x88x92(txe2x88x92180xe2x88x92txe2x88x92echo)j]i
where jxe2x88x921,2, . . . J and J is the number of echoes collected in a single Carr-Purcell-Meiboom-Gill (CPMG) sequence, where i=1, . . . I and I is the number of waiting times used in the pulse sequence, where Wi are the recovery times, TWi are the wait times before a CPMG sequence, and where t is the spacing between the alternating 180xc2x0 pulses and the echo signals. Although a conceptually valid approach for obtaining T1 information, this method is extremely difficult to implement in wireline, MWD, LWD or MWT applications because of the long wait time that is required to acquire data with the different TWs.
Proton NMR measurement is typically performed for well logging applications since hydrogen is abundant in reservoir fluids. T2 is very short in solids, but relatively long in liquids and gases, so that the proton NMR signal from the solid rock decays quickly and only the signal from fluids in the rock pores in the region of interest is seen. This signal may arise from hydrogen in hydrocarbon or water within the pores of the formation. The local environment of the hydrogen influences the measured T2 or xe2x80x9cspin-spinxe2x80x9d relaxation. For example, capillary bound fluid has a shorter T2 than fluid in the center of a pore, the so-called xe2x80x9cfree fluid.xe2x80x9d In this way, the NMR tool can be used advantageously to distinguish between producible fluid and non-producible fluid.
The NMR echo signals provide information about fluid and rock properties. Depending upon the goal of the investigation, various NMR measurement techniques can be used to obtain different petrophysical properties (e.g., partial and total porosities) or to discern multiphase fluids for hydrocarbon typing purposes. The different NMR acquisition techniques are characterized by differences in pulse timing sequences as well as repetition times between measurements. In addition, in wireline applications, multiple runs of NMR acquisition sequences with different parameters can be combined to enhance the analysis of the desired petrophysical information. However, in measurement-while-drilling applications or in measurement-while-tripping applications, it is not possible to make multiple runs, so that all the desired information must be obtained at one time while the borehole is being drilled or tripped.
The longitudinal relaxation time, T1, of oil phase carries important petrophysical information that is critical to hydrocarbon volumetrics, viscosity, and hydrocarbon typing analysis from NMR logs. The ratio of T1/T2 is a potentially useful information revealing in-situ reservoir fluid characteristics. While T2 can be estimated relatively easily, the estimation of T1 is challenging particularly when reservoir fluids contain more than one fluid, e.g., oil and water, or gas and water system.
Several methods to identify and quantify hydrocarbon reservoirs have been employed during the last few years utilizing the effect of different wait times on the measured NMR signal. Depending upon the fluid properties, the wait time (TW) determines the amount of the polarization that contributes to the measured signal. For example, Akkurt et.al. disclose a Differential Spectrum Method (DSM) based upon this effect in their paper xe2x80x9cNMR Logging of Natural Gas Reservoirsxe2x80x9d presented at the 36th Annual Meeting of the Society of Professional and Well Log Analysts (SPWLA) in 1995. This approach takes advantage of the T1 difference between hydrocarbons and water at reservoir conditions, and the short wait time (TWS) is chosen such that the fast relaxing water components are approximately fully polarized while the hydrocarbon components are not fully polarized. On the other hand, the long wait time (TWL) is typically chosen such that the hydrocarbon component is also nearly fully polarized. However, logging speed and overall signal to noise ratio (SNR) often dictates the selection of TWL to be less than optimal. Further, the TWL selected prior to acquisition may not be sufficiently long if the oil is lighter than expected. The T1 information is critical to correct the polarization effect after the log is acquired.
Analysis of dual wait time data for T1 estimation remains a particularly challenging task. In the prior art, a critical first step in the data analysis is to subtract the short wait time (TWS) echo data (ECHOB) from the long wait time echo data (ECHOA) in the time domain. Thus, practically, it requires that the two echo trains are at the exact same depth and have the same vertical sampling rate. This requirement makes it difficult to process multiple wait time echo trains acquired in different passes having different sampling rates, because of the cumbersome work involved in interpolating the two-dimensional echo matrices (typically, 500 elements per sample).
The poor signal to noise ratio (SNR) involved in the T1 analysis is another major difficulty in the prior art. The situation is worsened by the subtraction of ECHOB from ECHOA because the noise level increases while the signal strength decreased in the resultant differential data.
There is a need for a method of obtaining T1 information from multiple wait time data that provides stable estimates and does not suffer from very poor signal-to-noise ratio. Such a method should preferably be able to easily process data acquired with different logging passes with the same or different sampling rates without requiring the cumbersome work involved in interpolating two-dimensional echo matrices. The present invention satisfies this need.
The present invention is a method for acquiring nuclear magnetic resonance measurements of a porous medium using multiple wait times for determining the T1 relaxation time of oil in a hydrocarbon reservoir. The T1 values of water in the formation are represented by a distribution. In a dual wait time implementation of the method, data are acquired with a short wait time TWS chosen such that the wetting fluid phase (e.g., brine) is completely (or nearly completely) relaxed but the hydrocarbon phase is partially relaxed, giving a sequence ECHOA and with a long wait time TWL giving an echo sequence ECHOB. The individual echo trains are summed and the T1 values determined from the summed echo trains. The summation greatly improves the SNR and gives a significant improvement in the stability of T1 estimates. An equivalent method determines T1 values derived from the summation of the sum and difference of the individual echo trains respectively. The various summed values may also be used as for quality control of the data.